In a typical hydrocarbon producing well, a production tubing extends downwardly into the cased borehole and through the formation being produced. A packer, disposed on the production tubing above the formation, seals the lower borehole annulus. The upper borehole annulus, formed between the production tubing and cased borehole, is filled with well fluids, such as drilling mud, creating a static head above the packer to maintain control of the well. Hydrocarbons from the formation flow into the flowbore of the production tubing, via a perforated nipple as for example, to the surface.
In certain circumstances the production tubing above the packer may rupture. The rupture might occur, for example, because of a structural weakness in the production tubing. Such a weakness may be caused by corrosion combined with the production pressures from the hydrocarbons flowing through the flowbore of the production tubing.
If the rupture occurs at a point in the production tubing where the pressure of the upper borehole annulus immediately external of this point is greater than the production tubing flowbore pressure immediately internal of this point and therefore a pressure differential exists, drilling fluids from the upper annulus will tend to flow through the rupture and into the production tubing thereby killing the well. If the rupture occurs at a point in the production tubing where the static head pressure in the upper borehole annulus is less than the formation pressure in the production tubing flowbore, a pressure differential exists and the hydrocarbons in the production tubing will tend to flow through the rupture in the production tubing and into the upper borehole annulus. Thus, the pressure in the upper borehole annulus is increased and additional pressure is applied to the interior of the casing. Should the casing in the cased borehole have insufficient structural strength to withstand the increased pressure, the casing will rupture. The rupture potential in the casing is greatest when the rupture in the production tubing occurs near the surface where the static head pressure is at a minimum and the pressure differential is at a maximum. Further the differential external pressure on the casing is greater near the surface.
The problem may occur in either an oil well or a gas well. In an oil well, the pressure will increase due to the additional hydraulic head created by the leaking hydrocarbon liquid and/or gas. The gas mixed with the oil forms a gas pocket at the top of the upper casing annulus. In a gas well, the pressure will increase due to the gas pocket formed at the top of the upper casing annulus caused by the gas leaking from the flowbore into the upper casing annulus.
The consequences of a casing rupture and/or a well head blowout may be numerous and costly. Such a blowout may cause severe injuries to people present in the vicinity of the well. It may also cause severe material damage to the well and any other property adjacent to it. Furthermore, other economic losses will be sustained due to the loss of gas sales, equipment replacement, repair services, etc.
Downhole safety valves, disposed in the flowbore of the production tubing for the control of hydrocarbon flow therethrough, are well known. See for example the safety valves manufactured by Baker International, Inc. and Camco, Inc. disclosed in the 1980-81 Composite Catalog of Oil Field Equipment and Services, Volume 1 at pages 766-784 and 1359-1367, respectively. Other safety valves are disclosed in U.S. Pat. Nos. 2,798,561; 3,078,923; 3,782,461; 3,847,223; 4,161,219; 4,252,197; and 4,361,188. If it becomes necessary to kill the well and hydraulic control is lost, the safety valve can be closed from the surface to prevent flow through the production tubing.
One difficulty with many of the prior art safety valves is the requirement that they be actuated from the surface by the rig operator and are not automatically actuated when the need to close the production tubing flowbore arises and before extensive damage is done. Safety valve systems that require actuation of the valve by the rig operator are disclosed in U.S. Pat. Nos. 2,798,561; 3,078,923; 3,782,461; 3,847,223; 4,161,219; 4,252,197; and 4,361,188.
Another disadvantage in safety valves actuated from the surface is that the actuation is done through hydraulic lines extending from the surface and to the valve through the annulus. Such lines are exposed to the well fluids in the annulus and consequently high pressure and corrosive conditions. Therefore, they are susceptible to mechanical failure and frequent repair requirements. Furthermore, they contribute to the complexity of the operation due to equipment crowding and space occupancy in the well and in the annulus. Safety valve systems having hydraulic lines extending to the surface are shown in U.S. Pat. Nos. 2,798,561; 3,078,923; 3,782,461; 4,252,197.
Many prior art safety valves for closing the production tubing flowbore have certain disadvantages associated with the location of the valves. They may hydraulically restrict the flow of hydrocarbons in the flowbore. They may impede the usage of fishing tools lowered into the well for tool retrieval or other operations. Also, they may sustain mechanical damage caused by corrosion and vibration because of their continuous exposure to high pressure hydrocarbons flowing to the surface. Furthermore, once in the closed position they may fail due to the high pressure exerted directly beneath them.
Various methods are used to actuate downhole safety valves. U.S. Pat. Nos. 2,798,561; 3,078,923; 3,782,461; 4,161,219; 4,252,198; and 4,361,188 disclose applying hydraulic pressure on a sliding piston which, when reciprocated by hydraulic pressure, moves to actuate the safety valve. As disclosed in U.S. Pat. No. 4,361,188, such a sliding piston has a portion thereof exposed to annulus pressure and is reciprocated upon a predetermined increase in annulus pressure.
The prior art discloses means for biasing such a sliding piston in the normal position. The normal position generally being the position of the piston while the valve is closed. Various biasing means have been used such as a spring in U.S. Pat. Nos. 2,798,561 and 3,078,923, a compressible pressurized fluid in U.S. Pat. Nos. 3,782,461 and 4,161,219, or a combination of these in U.S. Pat. Nos. 3,782,461 and 4,161,219.
U.S. Pat. No. 4,361,188 discloses a well apparatus with a pressure accumulator for operating a safety valve. The pressure accumulator is charged downhole to the normal annulus pressure caused by the fluid static head and provides biasing means for maintaining the safety valve to an open position so long as the annulus pressure remains normal. Should a leak occur in the tubing or the packer causing the downhole annulus pressure to increase, the biasing force supplied by the pressure accumulator is overcome and the well apparatus closes the safety valve.
U.S. Pat. No. 4,161,219 discloses reducing the piston area exposed to hydraulic pressure to reduce the force required by the means to bias the piston in the normal position against the hydraulic pressure.
U.S. Pat. No. 4,109,725 discloses well apparatus for opening a circulation valve to provide fluid communication between the interior of a tubing string and the annulus for use in testing the well. Such valve is powered by a sliding piston which is biased by a spring to a position closing the valve and displaced to a position opening the valve by a force caused by pressure in the annulus around the apparatus.
It is well known to use sliding sleeves as a downhole flow control device mounted in the production tubing to control flow between the tubing and the casing annulus. Such sliding sleeves are shown in Volume 1 of the 1980-81 Composite Catalog of Oil Field Equipment and Services at pages 726-7, 882 manufactured by Baker International, Inc. and at page 1404 manufactured by Camco, Inc. These sleeves are operated by wirelines.
Such sleeves have many applications. They may be used for circulating purposes, killing a well, spotting acid or equalizing pressure between an isolated formation and tubing string.
U.S. Pat. No. 3,662,834 discloses a sliding valve for controlling flow between the tubing and casing annulus for various treating operations such as acidizing, fracturing, or sandconsolidating operations. A sliding sleeve is held in the normal position on the valve closing ports communicating the tubing with the casing annulus. To actuate the sleeve, a tubing plug is lowered into the valve body to close the flowbore of the tubing. The tubing is pressurized to apply pressure to one end of the sliding sleeve to shear pins holding the sleeve in the normal position and move the sleeve to the open position.
The prior art sliding sleeves are used prior to producing the well. Many sleeves require lowering a tool through the production tubing to actuate the sleeve to open flow between the tubing and casing annulus. Such tool cannot be lowered into production tubing while the well is producing since such a tool would be blown out of the well by the high formation pressure. Furthermore, such actuation from the surface would be manual and not automatic. Another drawback of such sleeves is that they are exposed directly to annulus fluids and therefore are susceptible to corrosion, fouling and mechanical stress and subsequent failure.
These and various other objects and advantages of the present invention will become readily apparent to those skilled in the art upon reading the following detailed description and claims and by referring to the accompanying drawings.
The above objects are attained in accordance with the present invention by the provision of a method of killing the well due to a rupture in the production tubing and for use with apparatus fabricated in a manner substantially as described in the above abstract and summary.